Advanced gas injection method and apparatus liquid hydrocarbon recovery complex

ABSTRACT

The invention provides for injecting of high-pressure miscible natural gas directly into a newly opened or previously produced liquid hydrocarbon reservoir to saturate liquid hydrocarbons to improve their mobility to flow toward and into producing wells. Concurrent injection of gas, miscible or otherwise, into the hydrocarbon zone&#39;s gas cap supplies additional pressuring effects to aid the resaturation process. Downhole float operated injectors are improved to operate at high pressures maintained within the wellbore to assure liquid hydrocarbon flow completely out of the formation. The improved injector system then senses the difference between liquid and gas and closes its valve to retain the gas within the wellbore. Rejected gas is redirected into the reservoir&#39;s gas cap for its continued benefits. Two liquid-producing systems utilize: 1) a liquid column and backpressure valve or, 2) an extended-float-length injector to permit the injector&#39;s float to open at high differential pressures created by maintaining the wellbore at pressure above liquid saturation levels.

FIELD OF INVENTION

[0001] The present invention relates to the process of improving and increasing liquid hydrocarbon recovery from an oil bearing reservoir by combining the effects of reservoir pressure increase and oil mobility increase through injection of natural gas or another miscible gas into the oil reservoir and injection of high-pressure gas into the gas cap above the liquid zone. Injection into the oil zone would be facilitated by use of horizontal borehole(s) or deep, high permeability, jet-type perforations from the main well bore. The advantages of the higher pressure and more mobile oil would be realized with a new production scheme utilizing a float-control valve system on the lower end of the production tubing which recognizes the difference between producible liquid hydrocarbons and gas, the latter which is desirable to retain downhole for automatic reinjection into the gas cap. Periodic reversal of the proposed invention-well system into production wells, and vice versa, is proposed for efficient drainage of the surrounding oil reservoir.

[0002] The High-Pressure Bottomhole Liquid Injector and Fluid Recovery Complex, hereafter called HPI invention addition (filed Jul. 5, 2002, U.S. PTO No. 60/393,515) relates to producing, offshore or onshore, excessively high-pressure reservoirs by producing liquid-only inflow at a high rate through the production tubing while maintaining the natural gas for its valuable liquid hydrocarbon recovery benefits within the reservoir, in the gas cap and in solution within the oil. The invention also relates to methods for recovering liquid hydrocarbons in shut-in wellbore-reservoir scenarios at new high-pressure levels to produce onto the surface while continuously maintaining pressure at levels never before produced at. These high pressure levels could be in primary high-pressure reservoirs or after continued high-pressure injection into the reservoir's gas cap and/or oil zone. It is shown and claimed that producing under such high pressures maintained in the reservoir's gas cap and/or oil zone and adjacent wellbore will recover liquid hydrocarbons to maximum levels of recovery unable to be reached by prior art systems.

BACKGROUND OF THE INVENTION

[0003] The basic production system proposed herein is described in U.S. Pat. No. 6,089,322 Jul. 18, 2000, U.S. Pat. No. 6,237,691 B1 May 29, 2001, U.S. Pat. No. 6,325,152 B1 Dec. 4, 2001, originally filed on Nov. 26, 1997 entitled “Method and Apparatus for Increasing Fluid Recovery from a Subterranean Formation”, and succeeding editions, which describe an downhole oil liquid injector (DOLI) and several new applications in various types of oil and gas producing scenarios. These production systems will be used in certain limited production scenarios, while an entirely new production configuration will be used in other scenarios to produce the GIC when the hydrocarbon reservoir injection wells are converted to production wells. Further improvements in the DOLI system are described herein to produce special downhole liquid-gas definition at high pressures and selection effects described.

[0004] The various processes used or proposed by the industry are described in U.S. Pat. No. 5,778,977, Bowzer et al, Jul. 14, 1998. These include established industry practices of: 1) injecting gas into the gas cap to retain or increase reservoir pressure, including the added benefit of encouraging gravity drainage of oil liquids retained in rock volumes depleted of primary mobile oil liquids; 2) application of oil-miscible gases, such as CO₂ or methane, above reservoir oil liquids and thus increase their mobility within reservoir pore spaces or fractured systems; 3) intermittent injection of gas and water, and even foam; 4) injection of CO₂ into vertically fractured reservoirs; 5) injection of a coolant to thereby increase the miscibility of CO₂ in crudes; 6) determination of the critical properties of various crude components to achieve first-contact miscibility. Principal problems discussed include the likelihood of injecting gas breakthrough back to the producing well(s) instead of creation of an effective flood front to drive the more mobile crudes toward lower pressure producing zones.

[0005] The Bowzer Patent further describes an improved process of recovering oil from an oil-bearing formation having a natural fractured network with vertical communication, and wherein gravity drainage is the primary means of recovery. CO₂ is concentrated in a displacing slug at the gas-liquid hydrocarbon contact and the slug is displaced downwardly to help move oil liquids toward a production well(s). A chase gas with a density lower than CO₂ (high percentage of nitrogen) is used to propagate the CO₂ downwardly. Also, nitrogen is used by the Mexican national oil company Pemex as a reservoir gas-cap expansion and oil repressuring mechanism in its giant Cantarell Complex offshore operation in the Bay of Campeche, Gulf of Mexico.

[0006] The HPI invention discloses a downhole oil liquid injector to produce liquid hydrocarbons and/or waters under extremely high pressure. The new, high-pressure bottomhole oil liquid injector (HPI), together with a liquid column back-pressure valve invention (LC-BPV) and/or with an addition entitled extended float system EFS, described later, is especially designed and invented to produce extremely high-pressure applications as shown in the gas injection complex GIC filed Jan. 9, 2002, with U.S. PTO No. 60/346,311, and “Method and Apparatus for Increasing Fluid Recovery from a Subterranean Formation”, U.S. application Ser. No. 08/978,702, with U.S. Divisional Patents issued U.S. Pat. Nos. 6,089,322; 6,237,691 B1; 6,325,152 B1; US Patents Pending Ser. No. 09/589,854 also, Patent Corporation Treaty (PCT) Ser. No. 09/589,854, PCT/US/97/2180. The HPI invention is also meant to produce other high-pressure scenarios other than the foregoing patents and patents pending.

SUMMARY OF THE INVENTION

[0007] Because of the importance of the major objects of the present invention (see “Statement of the Object of the Invention”, page 22) which are concerned with recovering vast amounts or presently unrecoverable (with prior art) liquid hydrocarbon reserves to become recoverable with this invention and, further, because the present invention's liquid hydrocarbon recovery processes have various phases, this section is given to also help explain a full disclosure of the present invention, to better understand the section entitled “Detailed Description of the Invention”.

[0008] The present invention discloses systems and methods: (1) to reenergize hydrocarbon reservoirs that are losing their original natural gas pressures and gas energy, both in solution within the oil as well as in the overlying gas cap in defined reservoirs in producing areas or fields by principally returning solution gas to the oil and, secondly, gas to the gas cap. (2) To reenergize hydrocarbon reservoirs that have lost solution gas in the oil by returning solution gas, energy and pressure to the in-place oil and, secondly, gas to the gas cap in fields that are now anywhere approaching marginal or considered to be marginal, thereby transforming unrecoverable crude oil to recoverable. (3) To newly energize, thereby maximally increasing oil mobility, gas energy and pressure in various primary hydrocarbon reservoirs that contain high, average, medium, and especially lower gravity (heavier) crude oils, again by energizing, adding solution gas to the in-place crude oil as well as increasing the pressure in the overlying gas cap. In order to do this, the gas injection repressuring system will target an entire hydrocarbon reservoir or chosen sections of that same reservoir in synchronized patterns.

[0009] This injection process is done in the following manner. Using a chosen “source gas” SG, the injection gas will be injected through the casing head annulus which communicates directly to the open horizontally drilled or perforated gas zone via the casing annulus. Here, any variety of chosen gases can be used, such as, but not limited to, natural gas, CO₂, or nitrogen (it should be noted that many fields are already using CO₂ or nitrogen). Multizone gas caps can be injected into individually. The gas cap injection process works to benefit the following oil zone injection process and helps recovery by added gas cap pressure.

[0010] The most critically important gas injection process is done through the central tubing injection string that will go through the first #1 packer which is located directly below the gas cap at the top of the liquid hydrocarbon (oil) zone. A bridge plug optionally can be used at the bottom of the permeable oil zone in order to seal off the area being injected into (horizontal boreholes or perforations.) Here, a second source gas SG2, is pressurized at the surface by a compressor assisted optionally with temperature control so that the SG2 will enter the liquid hydrocarbon zone as a compressed, pressurized gas, entering and going into solution with the in-place crude oil. Here, it is described that the oil zone will be horizontally drilled optionally with deep jet perforations (optionally air-drilled open hole for clean entry, eliminating drill mud blockage). Here, the horizontal borehole(s) can be one or more; however, the vertical wellbore can also be just perforated in certain configurations/wells. High performance, deeply penetrating jet perforations are available to communicate beyond the wellbore(s) through cement sheaths and the skin or permeability-damaged zone. The purpose of the deeper jet perforations is to allow the injected, pressurized gas to “permeate” as deeply as possible into the oil in the oil zone. If multiple oil zones exist that are separated by non-permeable barriers, the system described can be applied sequentially to individual oil zones.

[0011] When the crude oil zone reaches an optimum gas saturation level, with the injected gas having entered into solution within the crude oil through the permeable formation, the critically important recovery and production process will be ready. The foregoing, novel, process of injecting gas under pressure into the crude oil within its natural formation and maintaining that pressure throughout the reservoir and its producing wellbores entire production and recovery life is claimed in the present invention as a new and novel process which overcomes serious limitations the prior art cannot.

[0012] The following liquid hydrocarbon production and recovery process allows reenergized crude oil zones with newly injected solution gas (together with the present solution gas, if any) within the in-place crude oil to be recovered and produced under pressure, thereby not losing the crude oil's new life's mobility. Recovering and producing under pressure prevents solution gas and pressure from breaking out and escaping. Producing under pressure recovers the total oil injected with gas. The injection process and production process work together as a complete recovery process. Therefore, the novel advantages of the production phase process are claimed and overcome production and total recovery limitations that prior art cannot.

[0013] One major problem with producing liquid-only inflow under high pressure applications, as needed in the above application, is that excessively high bottomhole pressure will prevent the injector valve from opening. The HPI invention provides a workable solution to this excessive high pressure problem. An example is a reservoir that must maintain, in the reservoir and wellbore, 5,500 psi and above during its production from wellbore to surface. The present invention is designed to produce liquid hydrocarbons while maintaining the 5,500 psi (or above) at the oil intake at the bottom of the wellbore. The double-valve mechanism, which is designed to open at lesser pressures, will not open due to a very high-pressure. seal. In other words, a {fraction (3/16)}″ pilot tip and seat as designed in the prior art, that opens to relieve lesser pressures in order to dislodge the main tip off its {fraction (11/16)}″ port seat cannot dislodge with 5,500 psi opposing a partial vacuum being drawn by a pumping system or even at an atmospheric pressure tubing string. Therefore, a back-pressure valve is provided on the wellhead on the production tubing at the surface. The back pressure valve is preset to a back pressure that will be less than the operating wellbore pressure, but at the same time set high enough to prevent excessively high extremes in pressure differentials that would prevent the downhole injector's pilot valve from opening. Therefore, the back pressure is created, in part, for the purpose of this invention, by a predetermined column of oil or liquids in the tubing string. This column of oil directly above the HPI's discharge to the surface will be maintained by the back pressure valve BPV on the production tubing wellhead. Depending on well depth, the BPV will usually be set at a back pressure that will prevent a substantial volume of gas from breaking out of solution in the column of oil as it reaches its surface. However, once the BPV opens, produced crude oil will flow out, and only then will a substantial volume of gas break out of solution. The produced oil and gas will then be separated at the surface at the well's separating facilities.

[0014] In other words, in a high-pressure reservoir-producing operation that is producing with a pressure of 5,500 psi or above, the liquid column with surface back pressure valve can be adjusted to any range, lower or higher: For example, 4,500 psi, up to 5,000 psi can be created by a liquid column combined with BPV setting as desired, giving desired differential pressure of 500 psi to 1,000 psi, as needed, in order to open the injector valve's small pilot valve. This bottomhole operation differential created by a liquid column with an accurate BPV setting can vary, higher or lower, as needed in the injector-wellbore operation. In other words, the liquid column BPV (LC-BPV) helps control and allow the injector to operate at any extreme high bottomhole pressure, whether 1,000 psi to 5,500 psi up to 10,000 psi or higher, for a complete range of injected pressure relative to well depth As reservoir liquids enter the wellbore, they enter the injector to open its float mechanism by submerging it and are produced surging the lower pressure liquid towards the surface through the LC-BPV by the force of higher bottomhole pressure. Directly above the liquid column, the tubing wellhead BPV produces all incoming liquids at the surface at a high flow rate, injected by higher pressure annulus gas downhole. High bottomhole pressure injecting the incoming liquid hydrocarbon or water is the injection motor in the production tubing and the wellbore. This injection motor operates the HPI to produce liquids up the tubing and, in certain scenarios, maintains free high-pressure gas in the open gas zone as it enters the wellbore due to the incoming liquid's higher hydrostatic head pressure. The HPI on the bottom of the tubing string which leads to the surface is the casing annulus liquid pressure drawdown point. Special designs have been invented to prevent the high influx and accumulation of formation sand and debris that high volumes of liquid hydrocarbons could carry (see separate heading, entitled “Improved Downhole Oil Liquid Injector”). The HPI with the LC-BPV addition will produce all depth wells, shallow to deep, down to its limits of 10,000 feet, where depth limitations become apparent with this system, operating at 6,000 psi bottomhole pressure. The unique advantages of this invention are claimed and overcome pressure limitations that the prior art cannot.

[0015] The Extended Float System

[0016] The present invention provides a lengthened float to the DOLI as an alternative absolute solution having no high pressure or well depth limitations for the GIC high pressure reservoir wellbore operating system. The float is open at the top and closed at the bottom. The closed bottom is opened with a hole to receive a valve stem that operates the DOLI valve. The float device can be lengthened to various lengths by connecting light-weight float material collars threaded to receive reinforced threaded float ends. Collar connections can be made up inside float in order to maintain float's restricted outside diameter i.e., a float in designated lengths of approximately 20 feet to 30 feet can be connected by threaded collars and assembled as the tool is lowered into the wellbore at the wellhead. A lengthened outside jacket, also with threaded collars, is required for the DOLI, which likewise can be assembled first as the tool enters the wellbore (being made up at the wellhead.) The double valve will remain in the lower part of the float with its discharge line leading to the injector head, the injector head being the production tubing connection. The distinct advantage of a lengthened float is its added weight to open the {fraction (3/16)}″ pilot valve at very high pressures. An example: a {fraction (3/16)}″ pilot valve will open at 1,000 psi at an excess float weight of 27.6 pounds. Therefore, a {fraction (3/16)}″ pilot valve will open at 5,500 psi bottomhole pressure with an excess weight of 151.8 pounds created by an extended float in a total length of approximately 107 feet. Therefore, the lengthened float will open the pilot valve at 5,500 psi bottomhole pressure.

[0017] However, this system will discharge high pressure oil to a sudden drop in pressure in the tubing where a volume of gas breaks out of solution and flows crude oil towards the surface. The oil flow can be aided by fluid-operated gas lift valves. Above the lower gas lift valves on the tubing is located a Venturi tube device, which by the velocity flow through its inner throat creates a more efficient gas-liquid mixture piston sweeping action to help drive the flowing liquid column to the surface. As the flowing liquid hydrocarbon column is lifted in deeper wells, additional gas lift valves without Venturi tubes are spaced at higher levels and activated by the tubing pressure which flows liquids using high-pressure annulus gas onto the surface to well's tubing flow surface receiving system, typically a surface separator.

[0018] The extended float system EFS will produce all depth wells without any depth or pressure limitations. The unique and novel advantages of this invention are claimed and overcome all pressure and volume lift limitations that the prior art cannot.

[0019] Methods to Improve or Assist the HPI Operation

[0020] Because it is impractical to use an injector valve's pilot valve smaller than {fraction (3/16)}″ diameter pilot port, two other application procedures are proposed. If not already existing in subject producing wells, these two application procedures are: to drill a sufficiently deep rathole in the well and/or to ream out an open hole and rathole in order to allow larger dimension HPIs to operate, where feasible. A larger dimension injector with a larger float mechanism will help open a larger pilot valve with a larger main port against higher-pressure scenario extremes with the aid of the EFS and/or LC-BPV, the EFS being the preferable scenario. Also, this invention proposes to specially drill and complete new wells in order to accommodate an extra large dimension HPI system.

[0021] A Description of the Gas Cap Repressuring

[0022] The purpose of the gas cap repressuring (if it is an older gas zone) or newly pressuring (if it is an original new zone) is to increase the pressure on the gas cap to a chosen, high optimum pressure. Some of the injection gas here can go into solution with the oil (is solubilized into the oil—see CO₂ patent mentioned in background) on the upper crest of the gas cap.

[0023] A Description of the Liquid Hydrocarbon (Oil) Zone Repressuring

[0024] A pressurized gas is chosen that is identical or compatible with the reservoir liquid hydrocarbons. The purpose of the oil zone repressuring is severalfold: (1) To permeate the oil with pressurized gas which will go into solution with the oil under a designated pressure. Such pressure is created to the required optimum pressure by the surface compressor, which compresses pressurized gas into the oil zone. (2) As pressurized gas goes into solution within the oil, solution gas pressure returns to the oil. (3) As pressurized gas goes into solution within the oil, increasing the oil's mobility, it decreases its density, making it lighter by lighter density gas going into solution with a heavier density liquid (the in-place oil). (4) The combination of the aforementioned benefits makes the oil migrate more freely and rapidly towards the wellbores, horizontal and/or vertical, to be produced at a higher rate while efficiently enhancing ultimate recovery.

[0025] The pressured light oil buildup starts around the perimeter and slowly migrates into other, less energized, oil in the radius around the horizontal borehole. This process continues supplying solution gas into the surrounding oil, continually providing solution gas to the oil as it migrates outward, until it reaches saturation points at given moderate to higher pressures. This process tends to build up as rising, high-pressure injected gas meets gas-saturated oil, forcing the pressurized gas to the lower pressure, nonpressurized oil in the outlying borders. This high-pressured gas will move away from the repressured zone around the wellbore, contacting even more reservoir liquids as banks of saturated crude form.

[0026] Gas Injection Period

[0027] (See GIC, FIG. 1)

[0028] The gas injection period in chosen areas of the hydrocarbon reservoir into the gas cap is continuous or intermittent until a desired pressure is reached. Also, produced gas breaking out of solution from producing liquid hydrocarbons is reinjected. It should be noted that the gas cap will communicate throughout the upper part of the entire reservoir due to the permeability of the overlying gas cap. The oil zone repressuring is separate and will periodically cease when the oil zone reaches an optimum point to where the oil has both increased maximum mobility through pressurized gas saturation and is considered to be at the optimum pressure within the liquid hydrocarbon zone by injected gas reentering solution within the oil. At the ideal point, these injection (into the oil zone) wells will be converted to production wells.

[0029] When the GIC is injecting into the chosen sections of the reservoir rather than the entire reservoir, the sections that were producing will be converted to (oil zone) injection wells and the (oil zones) sections that were being injected into will be converted to producing wells. It should be noted that the injection and producing section patterns of the reservoir will be determined by studies of the reservoir. The feasibility of the alternative can be studied: to inject into the entire oil zone section of the reservoir at one time.

[0030] Here it is vitally important that the entire oil reservoir, both injection and production sections, will be continually held under pressure from day one throughout the production life of that reservoir by improved downhole oil liquid injectors with the EFS with optional packer configurations being permanently in place in all liquid hydrocarbon production sections, while other reservoir sections are being injected into. Due to this production method, only liquid hydrocarbons will be produced, while any gas breaking out of solution from the producing liquid hydrocarbons will be reinjected back into the reservoir system.

[0031] The Production Well System

[0032] Here it must be clearly explained and emphasized that the entire hydrocarbon reservoir, its gas cap(s), and liquid hydrocarbon zone(s) must be maintained under required high pressure levels, or shut-in pressure levels, in order to produce and recover the newly energized with solution gas and pressure liquid hydrocarbons within their given formations. These high pressure levels will be maintained in the wellbore and corresponding formations throughout the entire liquid hydrocarbon recovery process until the total liquid hydrocarbon is recovered. Only then will the gas cap gas be released and produced in any substantial volume.

[0033] In order to produce the hydrocarbon reservoir's newly pressured gas cap and oil zones, the DOLI is installed on a production tubing string in the deepest part possible of the wellbore (rathole, when possible), ideally below the oil zone horizontal borehole or perforations in order to obtain the maximum drainage/liquid reservoir drawdown from that zone. The DOLI will operate with an EFS as needed, which opens the DOLI's valve at the indicated bottomhole pressure. A packer is installed at the precalculated liquid hydrocarbon (crude oil) reservoir level below the gas cap. The packer will have a pressure relief valve discharge tube (PRVD tube). The PRVD tube will be set to open in order to relieve pressurized gas buildup in the upper well bore below the packer during the production process, through the packer into the upper reservoir gas cap within the wellbore. Any relief gas relieved through the PRVD tube can reenter the upper open gas cap in shut-in pressure scenarios. Relieved pressurized gas in the upper reservoir will reenter the open gas zone when outside gas is being injected into the gas cap via casing annulus once injection pressure exceeds gas cap reservoir pressure.

[0034] After the oil zone reservoir has been injected into through a horizontal borehole or boreholes, pressurized gas, dissolved/in solution with the oil, will gradually accumulate in the borehole radius of the oil zone. The gas in solution with oil levels will depend upon the prior period of pressurized gas injection. Injected pressurized gas will tend to surge out in a flooding pattern, subject to the reservoir's permeability, thereby seeking non-gas-saturated oil at its levels.

[0035] As wells are changed over from injection wells (in the oil zone) to production wells, the wells will be killed with a kill liquid (usually water or oil) in order to run the injector system. This kill liquid would then be swabbed back to bring the well around and put on production at its critical pressure level. Once the well is producing, it will stabilize according to the amount of liquid entering from the liquid hydrocarbon reservoir. Any and all liquid hydrocarbon or water production entering the vertical wellbore will accumulate into the lesser pressure tubing string. The injector tubing string to the surface is the casing annulus liquid draw-down point. It should be explained that each reservoir, according to its given pressure, will maintain a given fluid level within all the wellbores entering that reservoir, and, further, that this fluid level is consistent and varies only with backpressure on the wellbores. However, when the injector with tubing string to surface is present within the wellbores entering that reservoir, then, in effect, a new wellbore is created within the initial backpressured wellbore annulus. In a well operating with an EFS, this new injector to tubing string wellbore will be open to close to atmospheric pressure (the well's surface separating system) for flowing heads of oil through the EFS as gas breaks out of solution.

[0036] An Optional GIC Production Well Variation

[0037] Reference is made to FIGS. 1-12 of the following U.S. patents Granted to Kelley et al., U.S. Pat. No. 6,089,322 Jul. 18, 2000, U.S. Pat. No. 6,237,691 B1 May 29, 2001, U.S. Pat. No. 6,325,152 B1 Dec. 4, 2001, entitled “Method and Apparatus for Increasing Fluid Recovery from a Subterranean Formation”, particularly FIGS. 4, 5, 6, 7, 9, 10, 11 and 12, but not excluding FIGS. 3, and 8, for special production scenarios. It should be noted that in the production period of the repressurized/reenergized hydrocarbon reservoir, in the production wells, because of packer placement as seen in FIGS. 4, 5, 6, 7, 10 and 12, noted above, the reinjected gas, both in the gas cap and in the oil zone, would not escape/dissipate through the production system, as only repressurized/reenergized liquid hydrocarbons will be produced through the liquid injector on up through the artificial lift system in the production tubing on to the surface. An exception to this is when pressurized gas is produced with the oil and then is reinjected back into the reservoir injection system. This is noted in the use of FIGS. 3, and 8, where optimally released gas is reinjected back into the reservoir from the surface operation. The extended float system can be applied on these production scenarios where high pressure prevents the injector valve's opening.

[0038] An Important Variation of the GIC System, Entitled GIC Variation

[0039] The present invention is applied in primary or middle-aged fields, where high, average, to lower gravity crude oils are found with substantial gas in place in the virgin gas cap. This variation of the invention will be a valuable enhanced recovery method in areas where gas flaring is not permitted, or where gas pipelines are not available in many U.S. and world oil fields that lack gas handling and marketing facilities.

[0040] The natural gas found in the gas cap is produced to the surface for the sole purpose of being compressed by a compressor complex into a pressurized gas to be reinjected through a gas repressuring center tubing string to pass through one packer that is directly above the liquid hydrocarbon (oil) zone. This compressed (optionally temperature controlled) pressurized injection gas is pumped/compressed into the mother oil zone, where it finds its own compatible oil to go into solution with, thereby adding further solution gas to the in-place oil to increase its pressure and mobility for enhanced recovery.

[0041] Here the oil zone is opened with a horizontal borehole or boreholes with deep perforations, or with deep perforations in the vertical wellbore. The horizontal boreholes would be in the optimal part of the oil zone in order to fully saturate the oil by gas reentering solution with the oil in the radius around the borehole during the injection process. In very thick, massive zones, multihorizontal boreholes can be used at strategic liquid hydrocarbon (oil) levels in the reservoir. Where not feasible, deep jet perforations can be used in the vertical wellbore.

[0042] If needed, a different outside gas (example: other source natural gas, CO₂, or nitrogen) can be injected into the gas cap to increase its pressure to the optimum desired during and/or after drawing its natural gas off for repressuring/reenergizing its lower liquid hydrocarbon (oil) zone. However, a relatively large volume of gas cap gas is not needed in related volume when newly energizing and pressuring the oil zone to intensify enhanced recovery. Further, gas pressure should not be notably lost during injection into the oil zone, as no substantial gas volume is spent. Here, all gas breaking out of solution in produced liquid hydrocarbons during the production process can be reinjected into the reservoir's gas cap and/or oil zone through the surface injection system. The only gas used from the reservoir is to run the surface injection systems, compressors, pumping systems, etc.

[0043] Improved Downhole Oil Liquid Injector

[0044] The Improved Injector (Imp Inj) disclosed is one of the most functionally important bottomhole (BH) tools for the production of liquid hydrocarbons and waters for today's oil and gas industry.

[0045] The Imp Inj has two basic functions: (1) To allow liquids to enter the production tubing freely and instantaneously, without any hindrance, as they enter the wellbore from the reservoir. (2) To keep out any and all free gas under all various pressure conditions. There are four production condition problems that the Imp Inj is meant to overcome: pressures, volumes, sands and well dimensions. There are certain orifice size restrictions and pressure/volume/sand/well dimension problems that the Imp Inj will overcome that the prior art will not. The Imp Inj in today's industry will be producing extremely large volumes of liquids under very high BH pressures and in cases with severe influx of very fine formation sands.

[0046] The Pressure Problem

[0047] When the screen's rib section's slots are plugged with fine formation sand, excessive high pressure can cause the screen to collapse. Therefore, the screen must be built on a collapse-resistant, reinforced perforated pipe base in order to not collapse the entire upper part of the injector in excessively high-pressure wells. All other high pressure level problems for all depth wells are completely overcome by the extended float system (EFS). The HPI LC-BPV can be applied in certain restricted-type wells. These improvements have been described.

[0048] The Volume Problem

[0049] The screen's rib section slot orifice size openings are restrictive to large volumes of liquid hydrocarbons and/or waters (LH, W). Ex: The present screen is 3.75 ft. by 4.5 in. OD and has an open flow area of 39.0 sq. in. per foot. and has a flow rate of 750 barrels per day (bpd). For new application in wells that are producing in the thousands of barrels of LH, W per day, the screen length will be increased. Going from the present position, as seen in FIG. 2, Kelley et al in an upper direction, whatever screen length required, the top of it with its perforated pipe base would make into the Injector's head, i.e., the injector's head would be the production tubing and/or pump connection. Ex: If 3.75 ft. of screen equals 750 bpd and a well is producing 7,500 bpd, then the Imp Inj would need 37.5 ft. of screen section on perforated pipe. If the screen section goes over the standard tubing pipe 30 foot length, then screw couplings will be used.

[0050] An Improved Design of the Injector Screen for the Sand Problem

[0051] The injector screen will be used with the open slot rib section in a vertical position. A vertical screen is shown on the injector at the oil/liquid inlet level. The vertical screen provides more effective sand control, the vertical screen configuration prevents the liquid hydrocarbon/water contact that may carry fine formation sand from entering the screen rib section at the same level. The vertical slots allow the sands more space to settle out to the bottom of the wellbore. For more effective sand control, screen slots can be sized in 0.001″ increments to retain formation sand. This new vertical design is not seen in the prior art.

[0052] Well Dimension Problems

[0053] The present invention also discloses an improved injector housing (not illustrated in figure drawings) by providing a thin shroud made of thin steel or synthetic material, rather than the standard, thicker pipe material. The shrouded protective cover would be open at the top and closed or open at the bottom with a vertical screen inside thin, perforated shroud bottom when opened. The improved shrouded design is particularly for wells with little or no sand influx, which is not uncommon in many oil fields. If needed, a vertical sand screen inside a thin perforated shroud may also be used on the upper injector's oil and gas intake to keep out well debris. This thinner shrouded body to the injector would allow injector installation in smaller diameter wells which is common in many oil fields where its internal components can be changed proportionately and herein is claimed as a needed improvement to the invention.

STATEMENT OF THE OBJECT OF THE INVENTION

[0054] The present invention has several objects:

[0055] 1. To reactivate unrecoverable crude oil to become recoverable, such oil having lost its solution gas to flowing the oil with gas methods. The U.S. and the world have vast amounts of this unrecoverable oil still in place, sometimes as high as 80% of the original oil is left in place, dormant without solution gas.

[0056] 2. To produce the total in-place oil in reservoirs that are still producing oil with gas in solution.

[0057] 3. To enhance the recovery process of low gravity heavy crude oil. A large percentage of the U.S. and world oil supply is low gravity or heavy crude oil.

[0058] 4. To generally enhance the recovery of all gravity crude oils by adding solution gas and pressure to the in-place oil.

[0059] It should be noted that the production system in the above technology eliminates flowing oil with gas, as it allows only liquid hydrocarbon recovery while retaining gas and pressure in the hydrocarbon reservoir. This production system, combined with injecting solution gas and pressure to the in-place crude oil, is considered to be a major liquid and gaseous hydrocarbon recovery advance for the U.S. and world oil industry, as it will recover the majority of the U.S.' and the world's in-place liquid hydrocarbons while keeping the reservoir's natural gas within its natural gas cap, stored for future production methods. Thus, the foregoing objects with their U.S. and global benefits are claimed and overcome all prior art, U.S. and world-wide.

[0060] Other Applications of the Upper Gas Reservoir System for Gas Wells

[0061] In (average to very) deep, (average to very) high-pressure gas wells, when liquid hydrocarbons or waters are present in the lower section of the initial gas-bearing reservoir and it is desirable to produce these liquid hydrocarbons and/or waters, the upper reservoir with packer with PRVD tube at desired liquid hydrocarbon level with DOLI on a tubing string can be used to produce these liquids. A good example is deep, high pressure gas formations, which are mostly high-pressure gas but have valuable liquid hydrocarbons in the deeper, lower part. In these high-pressure gas wells, as the gas is producing off the casing annulus, it is also preferable to produce the valuable liquid hydrocarbons, condensate, light oil, heavier oil, or even incoming waters that are detrimental to gas well flow. This can be done by the application of the DOLI installed below on a production tubing string. Gas lift or pumping may be chosen, according to volume and pressure limitations and feasibility, to lift the liquid hydrocarbons or water to the surface. Because gas wells normally operate at a lower pressure than the exceptionally high pressure GIC, the EFS may or may not be required.

[0062] The Optimally Improved Bottomhole Oil Liquid Injector for CO₂ Operations

[0063] It should be explained that in CO₂ injection fields, it is undesirable to produce any liquid CO₂ that enters the wellbore after the production well/wells have normally adjusted to daily incoming production. Optionally, for CO₂ operations, the new injector shown in the provisional patent application GIC, FIG. 4, shows a spring, or with a springy hollow bellows, closed at the top and open at the bottom, affixed to the float bottom that holds the pilot valve stem that holds the main tip on the main port outlet into the injector's discharged intake line. This spring and/or bellows configuration will be designed to stay closed when any light gradient liquid CO₂ gas is present within the injector's float chamber. This special injector system can also benefit by the EFS and/or the LC-BPV addition, so that its valve will open under various high pressures.

[0064] As heavier gradient, gas saturated crude oil displaces the liquid CO₂ in the float chamber, this spring and/or bellows configuration is designed to compress by the downward movement of the float and the attached valve stem only after the weight of fluid in the float surpasses that of liquid CO₂ or whatever liquid hydrostatic pressure the float is designed to open with. This new spring and/or bellows addition to the injector is designed to open at a designated float-filled fluid density, coordinated with the injector's pilot valve orifice size.

[0065] For example, when the injector float is filled with liquid CO₂ in the closed valve position, the float will not submerge or open the valve due to the closing power of the spring and/or bellows below it. However, at any predesignated hydrostatic head/weight exceeding that of liquid CO₂, the spring and/or bellows would then be compressed, beginning at the opening of the injector's valve. The pilot valve's orifice size also is critical to the operation of this new design. The spring and/or bellows would be designed to fully compress when the injector's float is full of oil or the designated liquid.

BRIEF DESCRIPTION OF THE DRAWINGS

[0066]FIG. 1 illustrates the concept of compressing a miscible gas to high pressure and injecting it directly into a downhole liquid hydrocarbon bearing reservoir through a tubing string, both through perforations in the main casing string and/or a horizontal wellbore extending laterally into the liquid hydrocarbon bearing zone. Individually and above a packer isolating the liquid hydrocarbon zone, compressed high pressure gas is injected into the tubing-casing annulus and into a horizontal borehole and/or perforations into the gas cap overlying the liquid hydrocarbon zone. Arrows indicate miscible gas directly contacting liquid hydrocarbons and gas in the gas cap contacting a large area of the liquid hydrocarbon zone.

[0067]FIG. 2 illustrates a variation of high-pressure gas injection into the liquid-hydrocarbon bearing reservoir in which gas cap gas flows to a surface compressor through the tubing-casing annulus, isolated by a packer and is reinjected through the tubing string of the same well directly into its own compatible liquid-hydrocarbon zone.

[0068]FIG. 3 illustrates the components and operating principles of the Downhole Liquid Injector with its float-operated shutoff valve system permanently immersed in a liquid contained within the outer housing, and the sand screen featuring vertical slots around an internal ported base pipe.

[0069]FIG. 4 illustrates principal components of the extended float system in which float length is extended as much as four or five times that of conventional systems. The sand screen with its ported base pipe is shown elongated also by addition of one or more sections.

[0070]FIG. 5 illustrates a second liquid-hydrocarbon zone producing system in which an extended-length float system operates under high bottomhole pressure to supply partial columns or slugs of liquids into the production tubing strung, through which they are lifted to surface using gas lift valves connected to the tubing-casing annulus, and in cooperation with a new venturi jet system.

[0071]FIG. 6 illustrates a system of producing a well under high bottomhole pressures utilizing a Downhole Liquid Injector system that allows only reservoir liquids to flow into the tubing string. Shown on the tubing string is a packer directly below the gas cap with a vent tube and gas pressure relief valve into the gas cap. Within the tubing, a full column of reservoir fluid flows through a surface backpressure valve.

[0072]FIG. 7 illustrates schematically an improved Downhole Liquid Injector with an extended float system as it would look in the wellbore's rat hole below the open-to-liquid-hydrocarbon (perforated) zone, to better appreciated its extended length in the wellbore. Lengths of the improved liquid injector can vary from 120 ft. up to and over 530 ft. for high volume, excessively high pressure wells.

DETAILED DESCRIPTION OF THE INVENTION High Pressure Gas Injection into Liquid Hydrocarbon Reservoir Formations

[0073]FIG. 1 schematically depicts principal features of the present invention in which liquid hydrocarbons within the downhole liquid hydrocarbons LH reservoir, which can be in various stages of crude oil recovery. The present invention process is designed for crude oils of all gravities and is particularly vitally important for increasing recovery of all primary through marginal lower gravity heavy crude oils, of which there are vast reserve deposits in North America (U.S., Canada and Mexico), South America (Venezuela) and throughout the oil-producing world. This invented gas solution and pressure reentry process is also extremely vital for converting unrecoverable oil reserves to become recoverable that have been depleted from their original state of being saturated with natural gas that was originally in solution within the crude oil under their original high virgin reservoir pressure. These oil reserves are now marginal with the majority of the original in-place oil unrecoverable or becoming unrecoverable, and a great part of the world's reserves are presently or in the stages of becoming marginal. Therefore the present invention injection process is used for all various types of crude oil gravities in production stages of primary (new oil) through to marginal (old, becoming dormant oil). These in-place liquid hydrocarbons LH (crudes) are injected into with high pressure natural gas from a surface compressor C that is compatible with their oil types, preferably natural gas produced from their same, or similar, reservoir field areas. Therefore, the invention process's principal purpose is to reenergize with solution gas and pressure liquid hydrocarbon LH zones with high pressure natural gas where the crude is contacted directly with miscible natural gas pressurized by surface compression from compressor C and injected into the liquid hydrocarbon LH reservoir through an injection tubing string TS isolated from other reservoirs such as the upper gas cap GC and any deeper reservoirs by a packer P and bridge plug BP, respectively.

[0074] To most efficiently contact liquid hydrocarbons with the miscible natural gas, combinations of deeply penetrating perforations DP—such as those created by modern jet perforators—in the original casing string CS, and/or one or more horizontal boreholes HB, with the horizontal borehole's perforated casings directed away from the main wellbore in a predetermined direction and pattern to contact as much liquid hydrocarbon LH reservoir as possible. Miscible natural gas directed into the annulus A around and below the tubing string TS will contact liquid hydrocarbons LH deep within the reservoirs as well as those in the near-wellbore area, by continued compression from compressor C, increasing solution gas and pressure reentry. Resaturation of liquid hydrocarbons LH around the wellbore from which natural gas is in the process of breaking out or broke out as a reaction to producing early high rates at low wellbore pressures is critical for converting unrecoverable oil to recoverable crude oil for total crude oil recovery. Flowing oil with gas practices rapidly degas crudes and create channels of released gas into the wellbore which is increasing the “marginal oil” problem in hydrocarbon reservoirs throughout all U.S. and world oil fields. Early operators saw these problems manifested in increasing gas/oil ratios and falling crude production as they blew off reservoir gas in flush production operations.

[0075] Natural gas enters into miscibility with liquid hydrocarbons at extremely high pressures. Thus the present invention discloses injection of a natural gas directly into liquid hydrocarbon LH zones pressurized by surface compression.

[0076] For gas cap repressuring, CO₂ is commonly used, and sometimes nitrogen; however, in this invention miscible natural gas is preferably used, when available, for injection into the liquid hydrocarbon LH reservoir's gas cap GC. Therefore, natural gas is preferably used when available through deeply penetrating horizontal boreholes HB drilled from the main wellbore and open to the tubing-casing annulus A above the packer P. Such a configuration pressures a very large area of the gas cap GC as the more friction-free gas moves through the higher permeability away from the horizontal borehole HB. Gas cap GC injection contacts and repressurizes a large area of the liquid hydrocarbon LH reservoir to work in conjunction with the miscible natural gas injection. It will also act to increase the efficiency of gravity oil drainage from within any portion of the gas cap GC above the liquid hydrocarbon zone. The miscibility of CO₂ could be an alternative, or nitrogen with its various economic and environmental benefits, when available, where natural gas is not available.

[0077]FIG. 2 illustrates a claimed benefit of high-pressure natural gas injection in which the source of the high pressure miscible natural gas injection is the natural gas from the gas cap GC above its own liquid hydrocarbon LH zone and separated by a optimally placed packer P on the tubing string TS. The natural gas is produced from the liquid hydrocarbon LH reservoir's gas cap GC up through the upper wellbore annulus A above the packer P into a surface compressor C, which compresses the natural gas at high pressures into the injection tubing string TS and into perforations of the liquid hydrocarbon LH zone in the main casing string CS and/or one or more horizontal boreholes HB with deeply penetrating perforations DP. As will be emphasized in other features of the invention, gas is not produced with the liquid hydrocarbons, so essentially all gas remains in, or is circulated back into, the downhole system into gas cap GC and/or liquid hydrocarbon LH formations to achieve optimally increased liquid hydrocarbon LH (crude oil and condensate) recovery.

Improved Downhole Liquid Injector Features and Operation

[0078]FIG. 3 illustrates the primary components of the improved Downhole Liquid Injector DOLI disclosed in the present invention as the principal novel component of an improved downhole producing system process that will allow the system to produce liquid hydrocarbons at high pressures and volumes while maintaining these high pressures until the liquid hydrocarbons reach the production tubing having left the reservoir's formation in order to completely and thoroughly utilize of the newly increased crude oil mobility, crude pressure and reduced viscosity/density while retaining high pressure gases downhole in the gas cap and the liquid hydrocarbon reservoir in solution under pressure within the crude oil within the formation.

[0079] The Downhole Liquid Injector DOLI illustrated comprises the following basic components. (The extended float system EFS, a major component advance, improving the Downhole Liquid Injector DOLI's functionability to produce and recover high pressure reenergized crude oil is described in FIG. 4. The extended float system EFS and the vertical sand screen filter allow the Downhole Liquid Injector DOLI to produce all variable high pressures and volumes.) A float 12 constructed of a relatively thin steel, ex. 16 gauge, and 2½ or 3 in. in diameter, depending of wellbore and Downhole Liquid Injector DOLI size, approximately 24 ft. long, in conventional downhole injectors. The float 12 operates within an outer housing 10 of basic carbon steel of 4 in. outside diameter, typically containing male threads on top and bottom for connection of a top collar and a bottom female bull plug 11 with threads for either a male bull plug or an additional length of tubing for powdery sand collection.

[0080] The housing 10 will be permanently filled with a liquid level LL such as treated brine. The float 12 operates within this liquid, and its buoyancy, i.e., whether its rises or falls, depends on the density of fluids (liquids or free gases) that enter the top of the float 12 from the wellbore. Liquid hydrocarbons or water will add sufficient weight to cause the float to submerge. Gas will increase the buoyancy of the float, causing it to rise.

[0081] The function of float 12 movement is to open or close the shutoff valve SV attached to the bottom of the discharge line 13 extending from the bottom of the tubing string through the injector head 14 which contains the female thread for direct connection to the production tubing string. The bottom of the discharge line 13 is the valve seat 16 for the main valve tip 17. This main valve is {fraction (11/16)}-in. in diameter. The Downhole Liquid Injector DOLI of the invention features a double valve—through which pressure differential between wellbore, as applied into the float and onto the main valve, vs. lower pressure within the discharge line to the tubing—is reduced by the initial opening of a pilot valve of {fraction (3/16)}-in diameter. The pilot valve tip 18 is located on a short valve stem 19 attached to the bottom of the float. The tip contacts the {fraction (3/16)}-in. opening through the main valve tip which opens first, breaking the pressure differential seal and allowing the falling float 12 to pull open the main shutoff valve SV.

[0082] The injector is equipped with a novel, effective, vertical screen type sand/debris filter VF which is screwed into the top collar of the housing and into the bottom thread of the injector head 14. The screen filter of the invention features a base pipe with multiple ports 20 offering a high screen collapse rating and vertical screen slotted openings 21 featuring slots of 0.001-in. width for optimum efficiency and downhole life. The vertical slotted screen is an improved sand screen in this invention and is claimed over prior art as being novel and more effective.

[0083]FIG. 4 illustrates principal features of the invention's Extended Float System EFS in which the injector's float 12 length is substantially increased, by four to five times or more, to provide increased net float weight to open the shutoff valve's SV pilot tip against excessively high pressure differentials which provide a novel advance and positive solution for high-pressure liquid hydrocarbon production. In the extended float 12 system EFS, injector housing length 10 is increased by adding housing threaded pipe with threaded collar sections. The bottom bull plug arrangement is unchanged 11 in this injector version. The shutoff valve system of FIG. 3 remains essentially the same. The discharge tube 13 is equipped with fin-type centralizers 23 to keep float centered to discharge tube in wells deviated from vertical. And the exterior of the float 12 has half spheres of about {fraction (3/4 )} in. diameter 24 spaced on the outer surface to prevent friction contact of the float against the housing 10 internal diameter. Float sections are connected by internal special float material collars and threads 22 to achieve desired length and maintain original outside diameters. Each float section is specially precision-reinforced on the float 12 ends to be threaded for collar connectors 22.

[0084] The screen filter will be lengthened as needed to give the vertical filter VF surrounding the ported base pipe 20 now additional needed flow volume. For example, a 3.75 ft., 4½-in. outside diameter screen section can handle about 750 bbl/day flow. Additional filter sections 25 can be added for high liquid volume, as needed, by screwing into a collar connection 28. The top section screws into the injector head 14 into which the bottom of the tubing string TS is connected.

Production Systems Producing at Maintained High Pressure

[0085]FIG. 5 illustrates a production system of the invention which has a Downhole Liquid Injector DOLI (the actual tool is extremely long but is shown short for drawing) with an extended float system EFS and is located such that its long vertical screen filter VF liquid and gas intake rib section is in the vertical borehole near the bottom of the liquid hydrocarbon LH reservoir which produces into the wellbore from perforations in the casing string CS or in one or more perforated casing or open hole horizontal boreholes HB deeply penetrating the liquid hydrocarbon LH zone. The major portion of the extended float system EFS described in detail in FIG. 4 operates within a rat hole when possible or an extended portion of the casing string CS wellbore isolated at the lower end of the Downhole Liquid Injector DOLI with extended float system EFS by a bridge plug. The extended float system EFS alone, as detailed in FIG. 4, will be approximately 120 ft. or more in length for excessively high pressure wells.

[0086] The claimed advantage of the Downhole Liquid Injector DOLI with vertical screen filter VF and with extended float system EFS, is its ability to inject only reservoir liquids, hydrocarbons and/or water, under all extreme high pressure and volume conditions, that flow into the wellbore on into the production tubing string, while it detects the presence of free gas in the wellbore and positively prevents its flow into the tubing, while settling out on to the bottom wellbore possible high formation sand influx. Further features of the extended float system EFS invention are derived from its section lengthened float system which gives the float required weight, when submerged in liquid, sufficient to open the shutoff valve at excessively high pressures inside the bottom of the float, to introduce immediate liquid production. A prior serious limitation of the Downhole Liquid Injector DOLI and its float at conventional lengths is that excessive high wellbore pressures needed to maintain liquid hydrocarbons in a pressure-gas-saturated state for optimum inflow from the liquid hydrocarbon LH reservoir, create an unworkable or prohibitive seriously high pressure differential seal across the pilot tip of the two-part shutoff valve that prevents its opening.

[0087] Thus, the improved performance of the extended float system EFS allows opening of the {fraction (3/16)}-in. diameter pilot valve and subsequently the {fraction (11/16)}-in. main valve to allow production of all incoming liquid volume into the production tubing string TS at excessively high pressures. When the extended float system EFS opens the injector's shutoff valve SV, then the result is that extremely high pressure flows, columns or slugs of liquids into and upward in the tubing where liquid flow is aided by gas breaking out of solution and are further flowed to surface by entering gas lift from the higher pressured gas from casing annulus through required number of stage lift gas-lift valves GLV which are activated by sensing the pressure of the flowing liquid column above their given level in the tubing. The gas lift valves GLV will be spaced, as needed, above the liquid hydrocarbon LH zone into the tubing string TS onto the surface.

[0088] At the depth of the bottom of the gas cap GC and the top of the liquid hydrocarbon LH zone, a packer P containing a gas pressure relief vent tube VT is located on the tubing. The vent tube VT is to release any free gas pressure buildup in the wellbore that exceeds the required maintained backpressure on the liquid hydrocarbon LH zone, also discharge excessive gas pressure rejected by the extended float system EFS, so it can reenter the gas cap GC for conservation and benefits of gas injection.

[0089] A high velocity flow novel improvement to the liquid hydrocarbon lift system is the venturi jet tube VJ. The venturi jet has a short internal tube with a tapering construction in its middle that causes an increase in the velocity of flowing fluid which creates high velocity flow toward the well surface in the production tubing string TS. This high velocity flow is combined with the lift forces of gas breaking out of solution in the flowing liquid hydrocarbon, with the injected lift force of higher pressure gas being introduced by the gas lift valve GLV directly below the venturi jet tube VJ. The gas lift valve GLV introduces high pressure gas from the gas cap GC wellbore annulus A to flow liquid hydrocarbons being admitted by the Downhole Liquid Injector DOLI by the operation of the extended float system EFS opening at no pressure or volume limitations. The venturi jet tube VJ system with gas lift valves GLV is spaced at predetermined levels up the wellbore tubing string TS to efficiently lift all incoming volume of liquids with higher pressure gas. The number of venturi jets VJ with gas lift valves GLV will depend upon well depth and each venturi jet tube VJ with its gas injection source gas lift valve GLV will be effectively spaced at predetermined levels on the tubing string TS to lift all variety of depth and pressure wells, from shallow (1,000 ft.), average (6,000 ft.), deep (15,000 ft.), to very deep (30,000 ft.), or below and above. Approaching the tubing string TS wellbore surface, venturi jets VJ will not be used in order to keep a free open tubing space for swabbing the well when needed. Therefore, at a predetermined level only gas lift valves GLV mounted on outside mandrels will be used to complete high pressure injection gas lift from the open wellbore annulus A in order to lift all volumes of liquids at all various depths onto the surface of the well leading to the well's surface separating facilities.

[0090] Here it should be clearly noted that only lift gas will be used from the gas cap GC annulus A, that the gas cap GC will not produce gas to the surface. Rather gas pressure will remain shut in, as likewise pressure will be kept on the liquid hydrocarbon formation during its entire production and recovery life. The purpose is to keep high pressure on the reservoir's gas cap and the liquid hydrocarbon zone so that no substantial gas volume will break out of solution. If substantial pressure were released (primary or injected gas pressure) the liquid hydrocarbons would lose their recovery life mobility from the original or new solution gas and pressure within the liquid hydrocarbons.

[0091]FIG. 6 illustrates a second production system of the invention for producing liquids only from a liquid hydrocarbon LH reservoir through deeply penetrating perforations DP in the casing string CS or one or more horizontal boreholes HB and, as in FIG. 5, maintaining under pressure all reservoir fluids at a sufficiently high pressure within the wellbore in the annulus A to maintain inflowing liquid hydrocarbons' optimum mobility within the reservoir permeability by remaining gas saturated under pressure, i.e., the entire hydrocarbon reservoir remains under pressure as well as its producing wellbores in the field. The Downhole Liquid Injector DOLI operating within the permanent liquid level LL fill in the injector's housing senses the difference between high pressure gas and liquid flowing into the submerged float and opens its internal valve to allow only liquid inflow, hydrocarbon or water, into the tubing string TS. A packer P on the tubing string TS at the level of the top of the liquid hydrocarbon LH reservoir contains a gas pressure relief vent tube VT which allows excessive high pressure gas separated from the liquids in the wellbore to vent upward and reenter the gas cap for pressure conservation and continued benefits of gas injection.

[0092] The producing system invention shown serves to provide an increased pressure in the bottom of the tubing by maintaining a full column of fluid pressure within the tubing above the Downhole Liquid Injector DOLI and its associated check valve CV and adding to the column's pressure head with a backpressure valve BPV on the outlet of the tubing from the wellhead WH. This pressure in the tubing string on the discharge side of the Downhole Liquid Injector DOLI's shutoff is designed by varying the backpressure valve BPV setting and calculating fluid column density to prevent substantial volume of gas breaking out of solution at all levels in the full-column hydrostatic head with end results to reduce the differential across the valve between wellbore and tubing such that the weight of a conventional or extended float system as described in FIG. 4 will open the pilot tip ({fraction (3/16)}-in.) of the shutoff valve and thus allow the opening of the main ({fraction (11/16)}-in.) valve to permit incoming volume liquid production. This system is seen to work best for shallower to average depth wells without rat hole, with calculations made for solution gas-breakout in the upper liquid column at all levels in the tubing string TS. Also, the extended float system could be applied, where possible, in wellbore. It is specially noted that after the gas injection process is completed, the liquid hydrocarbon LH wellbore annulus A will require sufficient high pressure to lift liquids through the Downhole Liquid Injector DOLI all the way to the surface through the tubing string TS for this system to operate at given well depths.

[0093]FIG. 7 illustrates schematically the total improved Downhole Liquid Injector DOLI with an extended float system EFS in a vertical casing string CS wellbore in the well rat hole just below liquid hydrocarbon LH formation(s). Here it is shown with various sections of 24 ft. float length connected by special light weight float material collars for recovering liquid hydrocarbons in wells operating at estimated required pressures of 5,500 to 6,000 psi. Five float lengths, or more, would be required to produce the high pressure gas injection scenarios, as seen in FIG. 1 and FIG. 2. No other downhole tool or production system is available in today's oil and gas industry or shown in any prior art that will produce at these high pressure levels while retaining high gas pressure in the wellbore and the reservoir's formation(s)' liquid hydrocarbons LH and gas cap GC. This improved Downhole Liquid Injector DOLI with an extended float system EFS can produce at all high pressures for a variety of high pressure injection scenarios in wells up to 10,000 psi or above. Sufficient rat hole below the producing formations, if not available, will be specially drilled for this advanced recovery system. Also, all high extreme volumes of liquids present no limitations, as once the extended float system EFS opens, liquids flow at all incoming volumes to continue to drain the reservoir into the lesser pressure tubing string because the extended float opens with little liquid hydrocarbon volume. Even 250 ft. total of an extended section float will open with very little proportionate liquid hydrocarbon volume to open at 10,000 psi as a high pressure example. Therefore, the improved Downhole Liquid Injector DOLI with the extended float system EFS will keep the reservoir liquid hydrocarbon zone and gas cap maintained at shut-in high pressures during the entire production and recovery life of the reservoir after the application of the advanced gas injection process stage shown in FIG. 1 and FIG. 2, for which this production system was especially invented and designed. In other words, after the natural gas injection into the crude oil zone at the given high pressure level where gas enters miscibility with the liquid hydrocarbon, this pressure absolutely must be maintained at or above its critical pressure level, forward through the entire production and recovery stage of this invention until total in place liquid hydrocarbons (crude oil and condensate) are recovered from liquid hydrocarbon formations to surface. It should be noted that in all production scenarios of the present invention, high pressure must be maintained at shut-in scenarios, or very close, for the entire life of the liquid hydrocarbon recovery on both the gas cap and the liquid hydrocarbon formation(s) and their surrounding wellbore in order to produce the maximum total liquid hydrocarbons in place. It is estimated in average scenarios that approximately 5,500 psi to 6,500 psi or above must be maintained to fully recover all liquid hydrocarbons (crude oil and condensate) from their place in the formation on through the wellbore flow into the improved Downhole Liquid Injector DOLI with extended float system EFS, where only then, inside the production tubing string TS, can a substantial pressure drop be permitted for total ultimate liquid and gaseous hydrocarbon recovery.

[0094] Therefore, both the gas cap(s) and the liquid hydrocarbon zone(s) are always maintained shut-in during total liquid hydrocarbon recovery. This shut-in pressure is also maintained in the entire wellbore. The improved Downhole Liquid Injector DOLI with extended float system EFS on into the production tubing string TS to surface creates the liquid pressure drawdown as this tubing string with Downhole Liquid Injector creates a new wellbore that removes only liquid flow without restrictions and shuts off the entrance of all free gas, at all pressures. This new wellbore tubing string TS above the Downhole Liquid Injector DOLI uses lift gas from the wellbore annulus injected through gas lift valves GLV operating venturi jet tubes VJ. However, this lift gas is recycled back into the producing well system by the surface compressor in order to maintain required backpressure.

[0095] The foregoing disclosure and description of the invention from the total specification are thus explanatory thereof. It will be appreciated by those skilled in the art that various changes in the size, shape and materials, as well as in the details of the illustrated construction and systems, combination of the features, and methods as discussed herein may be made without departing from this invention. Although the invention has thus been described in detail for various embodiments, it should be understood that this explanation is for illustration, and the invention is not limited to these embodiments. Modifications to the system and methods described herein will be apparent to those skilled in the art in view of this disclosure. Such modifications will be made without departing from the invention, which is defined by the claims. 

What is claimed is:
 1. A system for increasing liquid hydrocarbon recovery from a downhole formation through an injection tubing string, comprising: a vertical wellbore opened both into the gas cap and the liquid hydrocarbon zones with horizontal boreholes and/or perforations; the injection tubing string from its connection to the surface compressor down the vertical wellbore to be open-ended by the selected opened liquid hydrocarbon zone; a packer selectively positioned above the downhole liquid hydrocarbon formation for sealing a well annulus outward from the injection tubing string; a bridge plug placed previously at an optimum level below the liquid hydrocarbon zone to isolate the choice injection area; injecting high pressure miscible natural gas from the surface compressor through injection tubing string below packer out the vertical tubing's open end directly into the open horizontal borehole(s) and/or perforations, compressing high-pressure natural gas into the selected liquid hydrocarbon zone(s), where it enters solution with the liquid hydrocarbon to increase its pressure and reduce its viscosity, thereby increasing its mobility, to be produced under high pressure.
 2. The system as defined in claim
 1. to inject miscible and/or other gases from surface at high pressures through a well annulus into existing gas cap formations through horizontal borehole(s) and/or perforations above the tubing packer and in communication with underlying liquid hydrocarbon formations.
 3. A method of increasing liquid hydrocarbon recovery from a downhole formation through an injection tubing string, comprising: a vertical wellbore annulus with horizontal borehole(s) and/or perforations indirect communication with the liquid hydrocarbon zone(s); positioning the injection tubing string from its connection to the surface compressor down the vertical wellbore open ended by the opened liquid hydrocarbon zone; positioning a packer above the liquid hydrocarbon zone for sealing the well annulus outward from injection tubing string; setting a bridge plug at an optimum level(s) below the selected liquid hydrocarbon zone(s), isolating the chosen injection area; injecting high pressure gas from surface compressor through injection tubing string below packer out the vertical tubing's open end directly into the open horizontal borehole(s) and/or perforations compressing gas deep into the liquid hydrocarbon zone(s) to enter solution with the liquid hydrocarbon; establishing increased pressure and viscosity reduction, increasing liquid hydrocarbon mobility through high pressure gas going into solution with liquid hydrocarbon to be recovered under a maintained high pressure level; and maintaining gas cap(s) and liquid hydrocarbon zone(s) under high pressure forward to the production and recovery process of this invention.
 4. The method as defined in claim 3, further comprising: injecting miscible gas and/or other gases through the well's upper annulus above top packer into the horizontal borehole(s) and/or perforated gas cap overlying the liquid hydrocarbon zone, and establishing increased overall formation gas cap pressure by surface compressor injection to increase efficiency of miscible gas injection into the lower liquid hydrocarbon zone.
 5. The method as defined in claim 4, further comprising: enhancing gravity flow of lower liquid hydrocarbons' flow movement on into producing wellbores by maintaining high gas cap pressure throughout the formation maintaining the selected hydrocarbon formation(s), both liquid hydrocarbon zone(s) and gas cap(s), under high pressure forward to the production and recovery process of this invention.
 6. A system for enhancing liquid hydrocarbon recovery from a downhole formation through an injection tubing string, comprising: a vertical wellbore opened both into the gas cap and the liquid hydrocarbon zone(s) with horizontal borehole(s) and/or perforations; a packer positioned between the liquid hydrocarbon zone(s) and the gas cap on the injection tubing string for sealing the well annulus outward from the tubing string, thereby isolating the gaseous hydrocarbon zone(s) from the liquid hydrocarbon zone(s); previously having set a bridge plug at an optimum level below selected liquid hydrocarbon zone(s) for isolating chosen injection area; the flowing of natural gas from the formation's opened gas cap(s) through the annulus above the top packer directly into a surface compressor; the surface compressor compressing the flowing gas cap(s') gas under high pressure into the injection tubing string; the injection tubing string, open-ended at the lower part of the vertical wellbore near the horizontal borehole(s) and/or perforations, injecting high pressure compressed natural gas directly into the open liquid hydrocarbon zone(s); and injected high pressure natural gas entering liquid hydrocarbon zone and going into solution with the liquid hydrocarbon, adding pressure and solution gas energy to the liquid hydrocarbon, thereby increasing its mobility and decreasing its viscosity with its own compatible gas cap(s') natural gas.
 7. A method of enhancing liquid hydrocarbon recovery from a downhole formation through an injection tubing string, comprising: a vertical wellbore annulus with horizontal borehole(s) and/or perforations in direct communication with both the liquid hydrocarbon zone(s) and the gas cap(s); positioning the injection tubing string from its connection to the surface compressor down into the vertical wellbore, where injection tubing string is open-ended by the open liquid hydrocarbon zone(s); positioning a packer above the selected liquid hydrocarbon zone(s) for sealing a wellbore annulus outward from the injection tubing string; previously having set a bridge plug at an optimum level below a selected hydrocarbon zone, isolating the chosen injection area; flowing natural gas off the formation's gas cap through the well annulus above the top packer directly into the surface compressor; the surface compressor injecting high pressure gas into the injection tubing string past the optimally set top packer, compressing gas out of the open-ended tubing directly into the opened horizontal borehole and/or perforated selected liquid hydrocarbon zone(s); establishing increased pressure and viscosity reduction, increasing the liquid hydrocarbon's mobility through high pressure miscible natural gas going into solution with its own compatible liquid hydrocarbon; and maintaining high gas pressure on the entire selected hydrocarbon formation's liquid hydrocarbon zone(s) and gas cap(s) through on to production and recovery process.
 8. The method as defined in claim 7, further comprising: maintaining a high gas cap pressure when the gas cap is lowered in volume and pressure by the surface compressor injecting miscible and/or other gases into the gas cap.
 9. An improved downhole injector for positioning downhole within or below a liquid hydrocarbon recovery zone in a vertical wellbore to permit all liquids, under all conditions, to freely pass from a downhole formation through the injector, first through a sand screen filter, then through an opened double shutoff valve, then through a check valve, and on into a production tubing string, while positively, under all conditions, preventing any free gases from passing through the injector into the production tubing string, the injector comprising: an injector housing having an double shutoff valve, having a main tip and port seat with a small, {fraction (3/16)}∴, being of a 0.0276″ cross-sectional area, pilot tip and port seat, affixed thereto; a liquid responsive float, open at the top and closed at the bottom, connected to the double shutoff valve by means of the pilot valve working stem, movable within the injector housing, subject to buoyancy created by permanent liquid surrounding the float in the injector housing; a double shutoff valve member movably responsive to the up and down movement of the float, thereby opening and closing the double shutoff valve as float fills or empties with liquids; a liquid discharge 1″ pipe leading from double shutoff valve through the float with fin-like guides extending from it to help center float without friction contact, discharge 1″ pipe making into injector's head at production tubing connection; a vertical slotted filter screen on the liquid and gas inflow entry on the upper injector housing, the vertical slots having increments of 0.001″, the vertical slotted filter screen preventing selectively-sized sand and/or debris particles from entering the injector housing; and a check valve directly above injector head tubing outlet fro preventing liquids from returning to injector.
 10. The improved injector as defined in claim 9, wherein the filter screen has vertical entry slots, thereby preventing sand particles from plugging screen slots by constantly entering the same horizontal slot area as in prior art, thereby multiplying screen rib entry areas for improved sand settlement outside of the screen area into the vertical wellbore annulus.
 11. The improved injector vertical slotted screen, as defined in claim 10, having a reinforced pipe base with multiports for excessive high pressure collapse resistance and the vertical slotted screen with its pipe base being variable in section lengths to accommodate low volume to high volume high pressure liquid inflow rates while screen sections will be threaded on their pipe base for connecting threaded collars in approximate lengths of 20′ to 30′.
 12. The improved injector as defined in claim 9, wherein the float is substantially extended, as needed, in section lengths by connecting threaded collars and reinforced threaded float ends to add float opening weight with increased float closing buoyancy in order to open injector's double shutoff valve at all variable excessively high pressures.
 13. A system for recovering liquid hydrocarbons from a downhole formation through a production tubing string, comprising: an improved downhole injector as defined in claim 9 positioned downhole within or below a liquid hydrocarbon recovery zone for passing formation liquids through the injector and into the production tubing string while preventing excessively high pressure free gases from passing through the injector; a packer positioned above the downhole injector for sealing the well annulus outward from the production tubing string at the optimum top level of the liquid hydrocarbon zone; a gas pressure relief vent tube sealingly extending upward through the packer, said pressure relief vent tube opening at a predetermined pressure such that excessive gas pressure can be relieved through the vent tube and into the annulus of the opened gas cap formation above the packer; a tubing pressure activated gas lift valve on an inside or outside pocket mandrel on the production tubing string directly above packer at gas cap bottom for injecting high pressure lift gas into production tubing; a venturi jet tube directly above gas lift valve centered inside the production tubing to increase gas-velocity flow through its venturi-shaped cone to create a more efficient gas-liquid mixture and sweeping action by forming a gaseous piston to help lift the flowing liquid hydrocarbon column to next gas lift combined with venturi jet tube stage lift uphole; one or more fluid operated gas lift valves optimally spaced on the production tubing string without venturi jet tubes to complete flowing liquid hydrocarbon process onto the surface; and a sufficiently opened internal tubing string depth for swabbing the well, when necessary; maintaining required high gas pressure on the entire selected hydrocarbon formation's liquid hydrocarbon zone(s) and its own wellbore annulus and gas cap(s) and its wellbore annulus throughout the entire production and recovery process of this invention.
 14. A method of recovering liquid hydrocarbons from a downhole formation through a production tubing string comprising: providing an improved downhole injector as defined in claim 9 and in entry communication with the production tubing string; positioning an improved downhole injector optimally bottomhole within or below an opened horizontal borehole or perforated liquid hydrocarbon zone; positioning a packer above an improved downhole injector for sealing a well annulus outward from the production tubing at an optimum top level of the liquid hydrocarbon zone entering the gas cap above; providing a gas pressure relief vent tube sealingly extending upward through the packer, said pressure relief vent tube opening at a predetermined pressure setting, venting excessive gas pressure buildup to the open gas cap above; providing a tubing fluid pressure activated gas lift valve mounted on an outside or inside pocket mandrel on production tubing string directly above top packer at optimum lower gas cap level, injecting high pressure lift gas into production tubing when predetermined tubing fluid pressure opens gas lift valve; providing a venturi jet tube directly above gas lift valve centered inside the production tubing string for increasing gas velocity flow through its venturi-shaped cone for creating a more efficient gas-liquid mixture sweeping action when flowing to form a gaseous piston to help drive flowing liquid hydrocarbons upward; providing additional tubing fluid pressure activated gas lift valves with venturi jet tubes optimally spaced uphole for stage-lifting deep wells; providing additional fluid operated gas lift valves on mandrels uphole on the production tubing string without venturi jet tubes for assisting flowing liquid hydrocarbon process on out to surface separating facilities; and providing a sufficiently deep internal production tubing string depth for swabbing well when necessary. maintaining required high gas pressure on the entire selected hydrocarbon formation's liquid hydrocarbon zone(s) and its wellbore annulus and gas cap(s) and its wellbore annulus throughout the entire production and recovery process of this invention.
 15. A system for recovering liquid hydrocarbons from a downhole formation through a production tubing string, comprising: an improved downhole injector as defined in claim 9, positioned downhole within or below a liquid hydrocarbon recovery zone for producing formation liquids through the injector and into the production tubing string while preventing high pressure free gas from passing through the injector; a packer positioned above the downhole injector for sealing a well annulus outward from the production tubing string; a gas pressure relief vent tube sealingly extending upward through the packer, said pressure relief vent tube opening at a predetermined pressure setting, such that excessive gas pressure can be relieved through the vent tube and into the annulus of the opened horizontal borehole and/or perforated gas cap above the packer; a back pressure valve for retaining high pressure on the production tubing string on the surface wellhead production tubing exit port; and a liquid column maintained in the production tubing string above the injector onto wellhead tubing backpressure valve, creating a total back pressure of gas-saturated liquid column plus surface back pressure valve setting to open at desired approximate differential needed to open injector double shutoff valve. maintaining required high gas pressure on the entire selected hydrocarbon formation's liquid hydrocarbon zone(s) and its wellbore annulus and gas cap(s) and its wellbore annulus throughout the entire production and recovery process of this invention.
 16. The system as defined in claim 15, further comprising: a total internal tubing back pressure, setting calculated using back pressure valve setting coordinated with liquid column in production tubing to prevent substantial gas volume from breaking out of solution as the liquid column reaches production tubing well surface.
 17. The system as defined in claim 15, further comprising: the use of the extended float system coordinated with the internal tubing back pressure to overcome the system's limitations and help prevent gas from breaking out of solution as liquid column reaches well's surface
 18. The system as defined in claims 18 and 17, further comprising: flowing liquid hydrocarbon production to surface without any artificial lift system in excessively high bottomhole pressure wells with little or no rathole at lesser well depths, so that high bottomhole pressure flows liquid hydrocarbon out at the surface wellhead tubing back pressure valve discharge. 